This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
To facilitate further discussion of the hydrocarbon recovery operations, FIG. 1 provides a schematic representation of a well together with surface facilities providing an exemplary production system 100. In the exemplary production system 100, a floating production facility 102 is coupled to a subsea tree 104 located on the sea floor 106. Through this subsea tree 104, the floating production facility 102 accesses one or more subsurface formations, such as subsurface formation 107, which may include multiple production intervals or zones 108a-108n, wherein number “n” is any integer number. The distinct production intervals 108a-108n may correspond to distinct reservoirs and/or to distinct formation types encompassed by a common reservoir. The production intervals 108a-108n correspond to regions or intervals of the formation having hydrocarbons (e.g., oil and/or gas) to be produced or otherwise acted upon (such as having fluids injected into the interval to move the hydrocarbons toward a nearby well, in which case the interval may be referred to as an injection interval). While FIG. 1 illustrates a floating production facility 102, it should be noted that the production system 100 is illustrated for exemplary purposes and the present discussion may be applied to wells coupled to any variety of surface facilities, such as may be implemented in land and/or water environments.
The floating production facility 102 may be configured to monitor and produce hydrocarbons from the production intervals 108a-108n of the subsurface formation 107. The floating production facility 102 may be a floating vessel capable of managing the production of fluids, such as hydrocarbons, from subsea wells. These fluids may be stored on the floating production facility 102 and/or provided to tankers (not shown). To access the production intervals 108a-108n, the floating production facility 102 is coupled to a subsea tree 104 and control valve 110 via a control umbilical 112. The control umbilical 112 may include production tubing for providing hydrocarbons from the subsea tree 104 to the floating production facility 102, control tubing for hydraulic or electrical devices, and/or a control cable for communicating with other devices within the well 114.
To access the production intervals 108a-108n, the well 114 penetrates the sea floor 106 to a depth that interfaces with the production intervals 108a-108n at different depths (or lengths in the case of horizontal or deviated wells) within the well 114. As may be appreciated, the production intervals 108a-108n, which may be referred to as production intervals 108, may include various layers or intervals of rock that may or may not include hydrocarbons and may be referred to as zones. The subsea tree 104, which is positioned over the well 114 at the sea floor 106, provides an interface between devices within the well 114 and the floating production facility 102. Accordingly, the subsea tree 104 may be coupled to a production tubing string 128 to provide fluid flow paths and a control cable (not shown) to provide communication paths, which may interface with the control umbilical 112 at the subsea tree 104.
Within the well 114, the production system 100 may also include different equipment to provide access to the production intervals 108a-108n. For instance, a surface casing string 124 may be installed from the sea floor 106 to a location at a specific depth beneath the sea floor 106. Within the surface casing string 124, an intermediate or production casing string 126, which may extend down to a depth near the production interval 108a, may be utilized to provide support for walls of the well 114. The surface and production casing strings 124 and 126 may be cemented into a fixed position within the well 114 to further stabilize the well 114. Within the surface and production casing strings 124 and 126, a production tubing string 128 may be utilized to provide a flow path through the well 114 for hydrocarbons and other fluids. A subsurface safety valve 132 may be utilized to block the flow of fluids from portions of the production tubing string 128 in the event of rupture or break above the subsurface safety valve 132. Further, packers 134 may be utilized to isolate specific zones within the well annulus from each other. The packers 134 may be configured to provide fluid communication paths between surface and the sand control devices 138a-138n, while preventing fluid flow in one or more other areas, such as a well annulus.
In addition to the above equipment, other equipment, such as sand control devices 138a-138n, may be utilized to manage the flow of fluids from within the well. In particular, the sand control devices 138a-138n may be utilized to manage the flow of fluids and/or particles into the production tubing string 128. The sand control devices 138a-138n may include slotted liners, stand-alone screens (SAS), pre-packed screens, wire-wrapped screens, membrane screens, expandable screens, and/or wire-mesh screens. The sand control devices 138a-138n may also include inflow control mechanisms, such as inflow control devices (e.g. valves, conduits, nozzles, or any other suitable mechanisms), which may increase pressure loss along the fluid flow path. Still additionally, gravel packs may be implemented together with the sand control devices. The sand control devices 138a-138n may include different components or configurations for any two or more of the intervals 108a-108n of the well to accommodate varying conditions along the length of the well. For example, the intervals 108a-108b may include a cased-hole completion and a particular configuration of sand control devices 138a-138b while interval 108n may be an open-hole interval of the well having a different configuration for the sand control device 138n. 
Conventionally, packers or other flow control mechanisms are disposed between adjacent intervals 108 to enable adjacent intervals to be completed differently, such as including sand control in one interval while not in an adjacent interval. While multiple interval wells are relatively common, and while the completions within the different intervals may be different, the planning associated with the design of these completions is generally based on a relatively limited set of information. For example, the design may include sand control equipment in one interval and not in another based solely on observations about the type of rock in the interval or on experiences in nearby wells. Other aspects of conventional well completion design will be understood from the following discussion.
While hydrocarbons have been a source of energy for many years, the technology available for use in extracting hydrocarbons from the ground continues to evolve. In part, the need for continually advancing technology comes from the increasingly challenging circumstances in which hydrocarbons are found. For example, more and more wells are located in areas that are geographically challenging. Geographic complexities, such as reservoirs in arctic conditions, in deep water, or in otherwise challenging subsurface formations (sandy, unconsolidated formations, shale formations, etc.), can increase the costs and operational risks of drilling a well and of treating the well should hydrocarbon production fall below acceptable limits or should there be another problem with the well (such as sand or water production). Even in otherwise conventional fields and formations, the costs of workovers and other treatments are high. In addition to the lost revenues while the well is not producing at target rates, the costs of equipment and manpower during workovers and other treatments can run into millions of dollars. Accordingly, researchers are continually attempting to identify ways to improve the efficiency of wells and reservoirs.
One measure of the efficiency of a well or reservoir is the dollars invested per quantity of oil produced. Clearly, the efficiency is reduced as costs and risks are increased through workovers and other treatments. However, efficiency is also reduced when production rates and/or total production volumes are low. Accordingly, well operators typically attempt to build robust wells, to postpone workovers and treatments, and to produce at rates that will return the greatest total volume with the lowest maintenance costs. While these goals are obvious in themselves, accomplishing these goals is far from easy due to the complexity of the operations.
From a very simplified perspective, hydrocarbon operations include effectively two primary components: 1) the reservoir in which hydrocarbons are stored; and 2) the well through which hydrocarbons are produced to the surface. Well operators take the reservoir in the condition provided by nature. As used herein, the term “well operators” is used generically to refer to the multitude of personnel involved in the production of hydrocarbons including geoscientists, reservoir engineers, drilling personnel, completions personnel, treatment personnel, business managers and planners, etc. In contrast, operators go to great length to engineer the well and to operate it in a manner that will maximize production. The well is the component that the well operators can manipulate, treat, modify, etc. to control the rate at which fluids are produced to the surface. As used herein, the term “well” is used broadly to refer to the wellbore itself (the hole created through drilling operations) and the equipment installed, disposed, or used in the well.
While the reservoir consists of the rock and natural earth into which the well is drilled, it may be understood as having two component parts: the near-well region and the native reservoir. As is well understood, the term reservoir is used herein to refer to regions of the earth in which hydrocarbons or hydrocarbon precursors are disposed or stored. In some implementations, the well drilled to connect to the reservoir may intersect the reservoir directly. In other implementations, the well may be disposed near the reservoir and be operatively connected to the reservoir through a variety of conventional means. Regardless of the relationship between the well and the physical location of the hydrocarbons, the drilling, the completion, and/or the existence of the well often affects the nature of the formation in the area adjacent the well rendering the near-well region distinct from the native reservoir in at least one manner, as is well understood by those in the industry. For the purposes of the present disclosure, the term near-well region refers to those portions of the formation that are affected by operations in the wellbore, such as drilling operations, completion operations, injection operations, fracture operations, acid treatments, etc.
While this relationship between the well, the near-well, and the reservoir has been appreciated for many years, conventional methods for designing wells and well operating plans, including completions and production operations, do not account for the dynamic behavior that affects well performance during the life of a well. For example, the near-well region that is the most dynamic portion of the formation is not distinguished from the reservoir during the reservoir modeling used to predict production rates and volumes. While reservoir models are increasing in sophistication, completion details and near-well phenomena are either neglected entirely or given simplistic treatment. For example, most reservoir models treat wells as boundary conditions providing an inlet to or an outlet from the overall reservoir system rather than the complex combination of equipment disposed in and methods performed on a well. Drilling operations and completion procedures, such as perforating, gravel packing, hydraulic fracturing, acidizing, etc., are, when considered, considered merely by means of a mathematical correction factor commonly referred to as a “skin factor.” Complex completions equipment are commonly neglected entirely in predicting production performance of a reservoir. In many circumstances, reservoir engineers determine predicted production performances with an assumed skin factor establishing the performance expectations. The drilling and subsurface engineers are then expected to provide a completed well with a skin factor less than the factor used in the assumptions. In many implementations, the estimated skin factor of the final completion design is never incorporated into the reservoir simulations for more accurate production performance predictions.
FIG. 2 is representative of a conventional inflow performance analysis 200 that is generally used to make well construction and completion decisions. In FIG. 2, flow rate 202 is plotted along the x-axis while flowing bottomhole pressure 204 is plotted along the y-axis. The initial inflow performance curve 206 is illustrated by the solid line while the initial tubing performance 208, or well performance, is illustrated by the dash-dot line. In effect, the conventional inflow performance analysis consists of predicting the initial production rate as a function of bottomhole pressure 204. The initial production rate is predicted using reservoir models adapted to model the ability of the reservoir to deliver fluids to a well at a particular location. Conventionally, that well is modeled as a single, uniform, static pressure sink into which fluids from the reservoir may flow. Additionally, the reservoir models used to predict the initial production rate fail to consider the nature or properties of the near-well region that is created by the drilling and completing of the well. The initial tubing performance 208 is predicted for a selected well design using conventional well modeling tools. The intersection 210 of the two plots identifies the target flowing bottomhole pressure and the target initial production rate for initial production operations. Initial tubing performance curves may be generated for a variety of well designs until a preferred combination of initial production rate and bottomhole pressure is identified.
While the inflow performance analysis 200 of FIG. 2 may be used to identify a target operating condition, it fails to consider several factors that are typically addressed by an operator before establishing the operating conditions for a well. For example, most operators understand that it is desirable to operate a well with some degree of uplift potential to naturally drive the produced fluids to the surface. Accordingly, while the well and completions are adapted to operate with the higher flow rates and pressures available from the reservoir, the well is typically operated to have a well potential somewhat lower than the reservoir potential. The degree of separation between the well potential and the reservoir potential is generally considered as the uplift potential. The uplift potential may be created or controlled during operation by choking the well or through other conventional means. In the interest of clarity, the terms reservoir potential and well potential should be understood to refer to the reservoir's potential to drive fluids toward the well and the well's potential to accept or receive such fluids and carry the same to the surface, each of which may be measured as a flow rate, a pressure, or other suitable measurement.
Additionally, many operators now recognize the desirability of multi-zone or multi-interval wells and may vary the well completion and/or operating conditions along the contact length of the well. Accordingly, the inflow performance analysis 200 may be performed for each interval to identify target operating conditions for that interval.
FIG. 3 presents a schematic representation of a conventional manner in which an operator may consider the reservoir potential and the well potential in designing a well, a completion, and/or operating conditions. The plot 300 of FIG. 3 represents the production potential 312 along the x-axis and the reservoir contact profile 314 along the y-axis. As illustrated, the well contacts the reservoir in four intervals 316 separated by packers 318. Additionally, the plot 300 presents the modeled reservoir potential 322 and the modeled well potential 324 in each of the intervals 316. As reflected in the illustration, the reservoir potential is conventionally modeled as a potential for the entire reservoir and is not modeled for specific completion intervals. Moreover, as reflected in the illustration, the well potential is modeled at a finer scale and may vary between the intervals. For example, interval 316d may have a higher well potential than interval 316c due to being completed as an open hole (316d) rather than a cased hole with perforations (316c). Still further, some well modeling tools may utilize full-physics modeling methods to produce a still finer scale model of the well potential, such as shown in interval 316b. The modeled well potential 324 of interval 316b may result from a variety of completion tools and/or from a variety of drilling circumstances. As discussed above, the well potential 324 may be intentionally established or controlled to be some degree less than the reservoir potential 322 to provide uplift potential.
While such planning and design methods have worked relatively well in the past, they are focused on making the initial completion designs and on maintaining production rates and volumes at levels established before the well is drilled. For example, while certain production problems may have presented themselves at a given time in a first well, by the time the second well, which is designed based on the experiences of the first well, reaches that given time in its life, the reservoir has changed dramatically through continued production operations and resultant depletion.
Thus far, much of the discussion has focused on designing wells and completions so as to maximize the initial production. While the balance between reservoir potential and well potential is important in the construction and completion of new wells, it is also important in considering proposed workovers of wells that are already suffering reduced production rates. For example, the relative impacts of different workover procedures and/or different completion equipment that may be installed during the workover may be considered. While these impacts are considered today, the consideration is limited to the same types of analysis described above—considering the inflow performance rate of the reservoir on average and the average tubular performance rate. In short, the conventional methods fail to adequately consider: 1) the range of completions technologies available; 2) the ability to customize the completion along the length of the well; and 3) the changes that occur in a well and in the near-well region as a reservoir is produced.
Well operators, and particularly completions engineers, are constantly challenged to produce wells at the highest rate possible and to extract the maximum total hydrocarbons possible from a reservoir. These objectives are often in conflict as producing a given well at high current rates may present risks to the well and/or to the reservoir. For example, a reservoir may have a high reservoir potential, which may be considered to be the potential or driving force moving fluids towards a well. A well completion designed to minimize the skin so as to allow maximum flow into the well may result in high initial production rates from such a reservoir. However, the same completion having low skin disposed in a poorly consolidated formation may lead to sand production in the well. Such a well would have high production rates for a short period of time before production is reduced due to excess sand production. Sand production is one of many challenges or obstacles that may be confronted when wells are designed merely to maximize initial hydrocarbon production rates.
These risks and challenges to maximizing total production are recognized by the industry. Various tools and equipment have been developed to provide complex completions in an effort to control the flow of fluids to maximize production while minimizing workovers. As introduced above, wells having multiple isolated intervals are common. Additionally, various examples of adaptable completions have been proposed, including completion equipment that is controllable from the surface and completion equipment that self-adapts under varying conditions in the well.
The increasing complexity of modern fields and reservoirs and the increasing complexity of modern wells and well technology have rendered the conventional well production planning tools insufficient for optimizing modern operations. While any of the various completions equipment configurations and methods may be applied in a given well to obtain or pursue optimized production rates, the challenge remains in identifying which type to use, how to configure the equipment, and where in the well it should be disposed for maximum cost benefit. Additionally, because the impact of the completion and/or workover decisions and operations on the formation is not reflected in the reservoir models of the conventional methods, it is not possible to determine how much more production, either in current rate or total volume, might be available through continued improvements to the completion.
The foregoing discussion of need in the art is intended to be representative rather than exhaustive. Technology addressing one or more such needs, or some other related shortcoming in the field, would benefit well planning and reservoir development planning, for example, providing decisions or plans for constructing, completing, operating, and/or treating a well and/or developing a reservoir more effectively and more profitably.